Casing joints, liners, and other oilfield tubulars are often used in drilling, completing, and producing a well. Casing joints, for example, may be emplaced in a wellbore to stabilize a formation, to protect a formation against elevated wellbore pressures (e.g., wellbore pressures that exceed a formation pressure), and the like. Casing joints may be coupled in an end-to-end manner by threaded connections, welded connections, and other connections known in the art. The connections may be designed so as to form a seal between an interior of the coupled casing joints and an annular space formed between exterior walls of the casing joints and walls of the wellbore. The seal may be, for example, an elastomeric seal (e.g., an o-ring seal), a metal-to-metal seal formed proximate the connection, or similar seals known in the art. In some connections, seals are formed between the internal and external threads. Connections with this characteristic are said to have a “thread seal.” As used herein, a “thread seal” means that a seal is formed between at least a portion of the internal thread on the box member and the external thread on the pin member.
FIG. 2 shows a cross section of a prior art made-up tubular threaded connection with wedge threads as disclosed in U.S. Pat. No. RE 30,647 issued to Blose, which is assigned to the assignee of the present invention and incorporated herein by reference. Wedge threads are characterized by threads with increase in width (i.e. axial distance between flanks 208 and 209) in opposite directions on the pin connection 201 and box connection 2000. Wedge threads are extensively disclosed in U.S. Pat. No. RE 34,467 issued to Reeves, U.S. Pat. No. 4,703,954 issued to Ortloff, and U.S. Pat. No. 5,454,605 issued to Mott, all assigned to the assignee of the present invention and incorporated herein by reference. This made-up connection consists of female box connection 200, and male pin connection 201. The made-up connection has overall connection length 202 (or the quantity L1) from pin nose 203 to box nose 204, and engaged thread length 205 (or the quantity L2) from the beginning of first engaged thread on the pin 206 to the end of last engaged thread on the pin 207. Note that engaged thread length 205 cannot always be measured in the same axial plane as implied by FIG. 2, as the start of the first engaged thread will not always lie in the same axial plane as the end of the last engaged thread.
The wedge thread-form has stab flanks 208, so called because they generally come into contact when the threaded connection is initially “stabbed” together to be made-up. The stab flanks 208 support the weight of the tubular before the connection is fully made-up. The thread-form also has load flanks 209, so called because they carry tensile load exerted on a made-up connection within a string of casing hanging in a wellbore. The thread-form on pin connection 201 has pin thread roots 210 and pin thread crests 211. The thread-form on box connection 200 has box thread roots 212 and box thread crests 213.
Referring to FIG. 2, one distinction between U.S. Pat. No. RE 30,647 issued to Blose and U.S. Pat. No. RE 34,467 issued to Reeves is that Blose discloses a wedge thread with clearance between the pin thread crest 211 and box thread root 212 and between the box thread crest 213 and pin thread root 210, while Reeves discloses a selected amount of interference between the roots and crests. Root-crest interference, in addition to the stab flank and load flank interferences inherent in wedge threads, provides a thread seal. This thread seal can provide a backup to other sealing mechanisms, or it can be used alone. The clearance disclosed by Blose is shown as gap A and gap B in FIG. 2. Wedge threads as disclosed by Reeves have replaced those taught by Blose in part because gaps A and B prevent the connection from being able to seal high pressures.
In some well construction operations, it is advantageous to radially plastically expand threaded pipe or casing joints in a drilled (“open”) hole or inside a cased wellbore. In a cased wellbore, radially expandable casing can be used to reinforce worn or damaged casing so as to, for example, increase a burst rating of the old casing, thereby preventing premature abandonment of the hole. In open hole sections of the wellbore, the use of radially expandable casing may reduce a required diameter of a drilled hole for a desired final cased hole diameter, and may also reduce a required volume of cement required to fix the casing in wellbore.
An expansion tool is typically used to plastically radially expand a string of casing or tubing disposed inside a wellbore from an initial condition (e.g., from an initial diameter) to an expanded condition (e.g., with a larger diameter). One common prior-art expansion process uses a conically tapered, cold-forming expansion tool 101 (commonly referred to as a “pig”) shown in FIG. 1 to expand casing in a wellbore. The expansion tool 101 is generally sealed inside of a pig launcher (not shown), which is a belled section attached to a lower end of a casing string that is run into the wellbore. Because the pig launcher must pass through the parent casing already installed in the wellbore, the pig launcher has an outer diameter that is less than a “drift diameter” of the parent casing. As used herein, the “drift diameter” is the maximum external diameter that can pass through a wellbore or casing installed in the wellbore. Generally, the drift diameter is somewhat smaller than the internal diameter of the wellbore or casing due to the wellbore not being perfectly straight. Because of this, a tool having exactly the internal diameter of the parent casing would be unable to move freely through the parent casing.
Typically, after running the casing string into the wellbore, the casing string is suspended inside the wellbore using slips (not shown). Then, drill pipe (not shown) is run into the wellbore and latched onto the expansion tool 101. After connecting the drill pipe, the weight of the casing string is supported by the expansion tool 101. The drill pipe is then used to further lower the casing string to the selected location in the wellbore. The expansion tool 101 includes a tapered section 98A having a taper angle 98B that is generally between 5 degrees and 45 degrees. The expansion tool 101 is generally symmetric about a longitudinal axis 97 thereof. The expansion tool 101 also includes a cylindrical section 96 having a diameter that corresponds to a desired expanded inner diameter of a casing string (not shown) that is followed by a tapered section 95. Note that in some instances, an expansion tool 101 may not have a cylindrical section 96.
The next step in this exemplary expansion process is to pump cement through the drill pipe and out of a cement port on the pig. The cement flows between the outside of the casing string to be expanded and the inside of the wellbore. After the selected amount of cement has been pumped, the cement port is sealed off, typically by a dart designed to seat in the cement port. The dart is usually pumped with drilling fluid through the drill pipe. Continuing to pump drilling fluid pressurizes the pig launcher, which drives the expansion tool 101 forward (i.e. upward toward the surface) and the casing further into the wellbore. As the expansion tool 101 moves forward, the casing string expands. Expansion generally continues until the entire casing string has been expanded. Depending on the length of expansion to be performed, the expansion process may be performed in length increments to remove lengths of drill pipe as the expansion tool 101 progresses upward. In many instances, the casing string will include a length of casing that remains inside the parent casing after expansion. The extra length of casing can be designed to act as a liner hanger for the casing string and to seal between the parent casing and the expanded casing string.
In this expansion process, a rate of radial expansion is determined by, for example, a total plastic strain required to expand the casing string, the taper angle 98A, and a rate of axial displacement of the expansion tool 101 through the casing string. Consistency of the expansion process is controlled by transitions along the expansion tool 101 and a cross-sectional area of, for example, lengths of casing that form the casing string, threaded connections that couple the length of casing, and the like.
The expansion tool 101 may be started at either the bottom or the top of the casing string depending on the tool design and the application. Radial expansion may be performed at rates of, for example, 25 to 60 feet per minute. Other expansion processes, such as expansion under localized hydrostatic pressure, or “hydroforming,” are known in the art, but are generally not used as much as cold-forming expansion processes. Other expansion tools for cold-forming the casing also exist. Various tools exist for use in cold-forming expansion processes.
A common problem with radial expansion of casing is that the connections can be damaged during the expansion process. Part of this damage is because the connections are stressed during make-up to ensure that the connections remain made-up while being installed in the wellbore. The additional stress experienced by the connections during radial expansion can cause the connection to fail. Typically, it is the box member that splits. Even if complete failure does not occur, connections may lose the ability to form a hydraulic seal. Connections that utilize metal to metal seals or thread sealing can lose the ability to seal after the deformation caused by radial expansion.
While various expansion methods, in particular the tapered expansion tool method, have proven to work quite well on casing strings, the expansion of made-up threaded connections can result in structural sealing problems. Threaded connections that undergo radial plastic expansion have a tendency to exhibit a non-uniform axial elongation and react differently to residual hoop stresses remaining after expansion. Specifically, male (pin) threaded members and female (box) threaded members deform differently during radial expansion. The box member will generally move away from the pin member during radial expansion. This is due in part to the relief of residual stress in the connection that exists from the make-up of the box member with the pin member. The radial movement of the box member from the pin member relieves some of the residual stress. This differential displacement phenomenon can result in a loss of preload in axially-engaged seals, making the use of conventional metal-to-metal seals (including, for example, shoulder seals) problematic for plastically radially expanded casing and tubing.
One of the more successful thread-forms for expandable casing applications is the wedge thread. One reason that wedge threads are a suitable thread-form for expandable casing applications is that they may not make-up against a radial torque shoulder (i.e. a positive stop), but instead typically make-up by nearly simultaneous contact of thread load flanks 209 and stab flanks 208. During the expansion process, axial stress in the connection will often cause a radial torque shoulder to fail when the compressive stresses at the shoulder exceed the compressive yield strength of the casing material. The advantages of a wedge thread are independent of the thread form used. When a dovetail-shaped or another closed thread form is used for the wedge thread, the wedge thread will also resist radial forces during and after expansion, which might tend to separate the pin connection from the box connection. An open thread form for the wedge thread may also be used, such as that taught by U.S. Pat. No. 6,578,880 B2, issued to Watts, and incorporated herein by reference.
As discussed above, the additional stress experienced by a connection during radial expansion can cause the box member to fail, or cause the connection to lose the ability to form a thread seal or metal to metal seal. The structural integrity and sealing ability of a connection are still needed after expansion. Thus, preventing the damage to the connection and providing a thread seal after expansion are highly desirable goals. Designing a connection for the purpose of being radially expanded could prevent failure of the box member and potentially maintain a thread seal.